Shale geomechanics for multi-stage hydraulic fracturing optimization in resource shale and tight plays

ABSTRACT

Systems and methods for improving production from wellbores include providing optimal fracture design parameters based on geomechanical analyses combined with geological, geophysical, and/or petrophysical knowledge. In at least one embodiment, the systems and methods include defining a well direction, defining a fracture spacing, selecting a fracturing fluid system and optimizing a fracture design, such as a complex multi-stage hydraulic fracture design. Such systems and methods can help minimize a learning curve associated with a wellbore or subterranean formation and optimize the hydraulic fracturing operation for a hydrocarbon reservoir.

FIELD OF INVENTION

The embodiments disclosed herein relate generally to modeling oilfieldformations, and more specifically relate to methods and systems fordesigning hydraulic fracturing operations and optimizing wellproduction.

BACKGROUND OF INVENTION

Drilling optimization in resource shale and tight plays can be similarin some respects to that of conventional plays. However, differences mayexist, such as with respect to time-dependent wellbore stability due toexceptionally long horizontal well drilling.

Developing hydrocarbon formations, such as resource shale and/or tightplays, can be extensive and demanding, particularly when determining asuitable multi-stage fracture (or “frac”) stimulation design. Althoughdrilling optimization in resource shale and tight plays may be similarto that of conventional plays in some respects, some differences exist,such as with respect to time-dependent wellbore stability because ofrelatively long horizontal well drilling. After successful developmentof, e.g., the Barnett shale, other resource shale and tight plays havebeen commercialized all over North America, and such efforts are nowextending elsewhere, such as to Central and South America, Europe,China, Australia, and Russia. The success of resource shale and tightplays has at least partially derived from technological advancementsduring the past ten years, such as large volume multi-stage hydraulicfracturing in horizontal completions, passive microsiesmic monitoringand expanded use of three-dimensional (“3D”) seismic of the fields. Suchtechnological advancements in resource shale and tight plays can presentunique engineering challenges with respect to geomechanics, such aslong, horizontal well drilling and completion methods that allow complexmulti-stage hydraulic fracture stimulation design. Horizontal drillingcan create significant wellbore stability issues, which may bestress-induced and time-dependent, from fluid-formation interaction.

A common approach in some areas has been to duplicate the so-calledBarnett design, such as by using a slick water fracturing fluid with alow concentration of proppant. However, the Barnett design can berelatively inefficient in fields other than the Barnett shale, such asin the Haynesville, Bakken, and Eagle Ford shales. A recent trend fordeveloping resource shale and tight plays has been to attain an analogfield, duplicate the design optimized in the analog field and furtheroptimize its design by trial and error. However, this approach canrequire a considerable learning curve and associated costs to determinethe optimal multi-stage fracturing design for one or more wellbores. Thepresent disclosure is directed to systems and methods for optimizingfrac designs for wellbores.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of a drilling rig that may be used withone of many embodiments of a hydraulic fracturing process according tothe disclosure.

FIG. 2 is a schematic perspective view illustrating one of manyembodiments of a hydraulic fracturing process according to thedisclosure.

FIG. 3 is a table illustrating relationships between hydraulic fracturegeometry, stress anisotropy and brittleness of exemplary reservoirformations according to the disclosure.

FIG. 4 is a perspective view illustrating one of many examples of stressoverlap in an alternating sequence fracturing operation according to thedisclosure.

FIG. 5 is a flow diagram illustrating a method for implementing one ofmany embodiments of a hydraulic fracturing model according to thedisclosure.

FIG. 6 is computing system that may be used with one of many embodimentsof a hydraulic fracturing process according to the disclosure.

DETAILED DESCRIPTION OF DISCLOSED EMBODIMENTS

As an initial matter, it will be appreciated that the development of anactual, real commercial application incorporating aspects of thedisclosed embodiments will require many implementation-specificdecisions to achieve the developer's ultimate goal for the commercialembodiment. Such implementation-specific decisions may include, andlikely are not limited to, compliance with system-related,business-related, government-related and other constraints, which mayvary by specific implementation, location and from time to time. While adeveloper's efforts might be complex and time-consuming in an absolutesense, such efforts would nevertheless be a routine undertaking forthose of skill in this art having the benefits of this disclosure. Italso should be understood that the embodiments disclosed and taughtherein are susceptible to numerous and various modifications andalternative forms. Thus, the use of a singular term, such as, but notlimited to, “a” and the like, is not intended as limiting of the numberof items. Similarly, any relational terms, such as, but not limited to,“top,” “bottom,” “left,” “right,” “upper,” “lower,” “down,” “up,”“side,” and the like, used in the written description are for clarity inspecific reference to the drawings and are not intended to limit thescope of the disclosure.

Applicants have created systems and methods for improving productionfrom wellbores. The systems and methods of Applicants' disclosure canhelp minimize a learning curve associated with a wellbore or formationand, in at least one embodiment, can include providing optimal fracturedesign parameters based on geomechanical analyses combined withgeological, geophysical, and/or petrophysical knowledge. In at least oneembodiment, a method as disclosed herein can include defining a welldirection, defining a fracture spacing, selecting a fracturing fluidsystem and optimizing a fracture design, such as a complex multi-stagehydraulic fracture design. A method as disclosed herein can includedetermining one or more geomechanical variables for at least partiallyimproving production, such as well placement, horizontal well direction,stage isolation method, stage interval, perforation location, fracturingfluid system and fracturing proppant. In at least one embodiment, asystem can include one or more databases integrating some or all knowngeomechanical information obtained from geological, geophysical,petrophysical and laboratory data for a field or formation. Geophysicaland petrophysical analyses of natural fractures and faults can also beincluded and, in at least one embodiment, can be used for one or morestages of a fracture design, such as for a final or other stage of amulti-stage hydraulic fracture design, as explained in further detailbelow.

The systems and methods of the present disclosure can play an importantrole throughout the entire life of a reservoir, which can, but need not,be an unconventional reservoir such as a resource shale or tight gas/oilplay. For example, as emerging fields, such as those in Central/SouthAmerica, Europe, China, Australia, Russia and elsewhere, are beingexplored and placed in well planning or development phases, the benefitsof the systems and methods disclosed herein can be realized not only forthe first well drilled in a particular location but for each welldrilled in a particular reservoir, which can be any reservoir inaccordance with a particular application. Further, the systems andmethods disclosed herein can be applied during any phase of hydrocarbonor other operations, such as, for example, exploration phases, wellplanning and development phases and other phases, such as drilling,completion and production phases, separately or in combination, in wholeor in part.

In at least one embodiment, a method as disclosed herein can includebuilding one or more models for estimating properties or attributes of aformation, such as a mechanical earth model for modeling one or moregeomechanical characteristics of a formation. A mechanical earth model,along with the other models of this disclosure, can be one-dimensional(“1D”), two-dimensional (“2D”) or three-dimensional (“3D”), and can be alone model, such as a stand-alone model, or a collective model, such asby being a part of one or more other models, for example, an earthmodel, a reservoir model, or another model. A model can comprise anydata or other information according to an application. For example,model data can include information derived from mechanical or othertesting, such as core analyses, and can include any of numerouscharacteristics associated with a formation, such as, for example, shaleanisotropy, heterogeneity, pore pressure and other variables, such asin-situ stresses. The systems and methods of the present disclosure,which can, but need not, be wholly or partially implemented by way of acomputer-implemented model, can be particularly advantageous fordeveloping unconventional fields, including for performing drilling andcompletion optimization as discussed in further detail herein.

In at least one embodiment, a method as disclosed herein can includebuilding a geomechanical model for a resource shale or other play, whichcan include at least partially defining anisotropy and heterogeneity ofa formation and developing or optimizing a multi-stage fracture designfor the formation. A method as disclosed herein can include developingor optimizing a drilling phase for a formation, which can includeperforming one or more analyses for determining or estimating drillingcharacteristics of the formation. For example, performing a wellborestability analysis can include determining shear failure, casing shear,critical stresses (e.g., critically stressed fractures or faults) orother factors, such as time-dependence. A method as disclosed herein caninclude performing a wellbore trajectory analysis for determining thelength, direction and overall path of a wellbore. A method as disclosedherein can include determining one or more drilling tools or properties,which can include identifying any number of factors, such as one or moreof mud weight, mud chemistry, bit selections, trajectory, proper landingof the lateral, data collection during drilling, casing, etc.

A method for optimizing completion of a well can include developing areservoir-specific multi-stage hydraulic fracturing design formaximizing the recovery of hydrocarbons from a formation. In at leastone embodiment, a method as disclosed herein can include determining ahorizontal or other wellbore direction, determining fracability,determining hydraulic fracture geometry, assessing risk of faultreactivation, determining lateral well spacing, determining hydraulicfracturing intervals and determining one or more fracture (i.e.,perforation) locations along a wellbore, separately or in combination,in whole or in part. In at least one embodiment, a horizontal welldirection can be determined based on a planned or potential fracturedesign, e.g., longitudinal or transverse. In at least some cases, awellbore, such as a horizontal wellbore, can be formed in the same or asimilar direction as the direction of a minimum horizontal stress in aformation. For example, a well may be drilled parallel to a minimumhorizontal stress vector for achieving transverse hydraulic fractures ina reservoir. If the stresses and stress directions within a formationare not considered or otherwise analyzed correctly, created hydraulicfractures can be less than optimal, which can include developingunwanted complexities or forming in unwanted directions (e.g., byreorienting parallel to a maximum stress direction). This can result inunwanted effects, such as undesired multiple fractures, creation ofnear-well tortuosity and decreases in near-well fracture conductivity,which can lead to increasing treating pressure and even inducing earlyscreenouts. A local direction of maximum horizontal stress to achieveproper transverse hydraulic fractures can, in at least one embodiment,be defined from wellbore image logs, oriented cross-dipole sonic logsand/or micro-seismic monitoring data. Because of the inherentdifferences, e.g., in anisotropy and heterogeneity, of respectiveresource shale, tight reservoirs and other formations, it can beadvantageous to carry out multi-stage fracturing designs onreservoir-specific bases. While one or more embodiments of Applicants'disclosure are described in further detail below with reference to anexemplary reservoir and associated orientations, a person of ordinaryskill in the art having the benefits of the present disclosure willreadily understand that such examples are but a few of many and that thesystems and methods disclosed herein can be applied to any reservoirformation or wellbore.

Referring now to FIG. 1, an oil drilling rig 100 is shown that may beused for hydraulic fracturing in connection with certain aspects of theexemplary embodiments disclosed herein. The drilling rig 100 may be usedto drill a wellbore 10 in a reservoir 20 from a surface location 12,which may be a ground surface, a drilling platform, or any otherlocation outside of the wellbore 10 from which drilling may becontrolled. The drilling rig 100 has a drill string 26 suspendedtherefrom composed of a continuous length of pipe known as drillingtubing that is made of relatively short pipe sections 51 connected toone another. The drill string 26 typically has a bottom hole assemblyattached at the end thereof that includes a rotary drilling motor 30connected to a drill bit 32. Drilling is typically performed usingsliding drilling where the drill bit 32 is rotated by the drilling motor30 during drilling, but the drilling tubing is not rotated duringdrilling. The ability to perform sliding drilling, among other things,allows the trajectory of the drill bit 32 to be controlled to therebydrill in an angled direction relative to vertical, including ahorizontal direction.

FIG. 2 is a schematic perspective view illustrating one of manyembodiments of a hydraulic fracturing process according to thedisclosure. In at least one embodiment, a method as disclosed herein caninclude determining fracture spacing, or perforation interval, for areservoir or wellbore, such as for at least partially enhancingproduction from the reservoir based on fracture complexity orconductivity. Finding an optimal or other perforation interval betweenhydraulic fracturing stages can improve artificial enhancement ofcomplex network fractures and fracture conductivity in some formations,which can include resource shale, tight plays, or formations where aplanar form of hydraulic fracture geometry is present or anticipated.The effects of fracture spacing, i.e., enhancing complex networkfractures and non-propped fracture conductivity, can be universal forsome or all multi-stage fracturing techniques (e.g., sequence, zipper,etc.). However, for illustrative purposes, FIG. 2 shows one alternatingsequence fracturing (“ASF”) operation known as the “Texas two-step,”which is but one of many examples. In such a fracturing operation, thewellbore 10 can be perforated in a plurality of locations along itslength for hydraulically fracturing the reservoir 20, which fracturingcan occur in various sequences, or stages. As shown in the portion ofwellbore 10 of FIG. 2, for example, a fracturing operation can includethree adjacent perforations for fracturing, which are referred to hereinand referenced in FIG. 2 as fracturing Stages 1, 2 and 3 according tothe order in which fracturing occurs. Once fracturing Stages 1 and 2 areperformed, hydraulic fractures (e.g., complex planar) can be generatedwith limited reservoir contact and fracture conductivity normal to thehorizontal wellbore 10. However, as a result of fracturing Stages 1 and2 taking place, stress overlap can increase stress in one or moredirections between the two fracture stages, which can decrease stressanisotropy between the two fracture locations. For example, wherewellbore 10 is parallel to the direction of minimal horizontal stress ina formation (the direction of Sh in the example of FIG. 2), fracturingStages 1 and 2 can result in stress overlap increasing stress in the Shdirection between the stages. Fracturing in Stage 3 can create morecomplex fractures, such as complex network fractures. In such anexample, which is but one of many, fracturing Stage 3 can create morereservoir contact and better non-propped fracture conductivity normal toa horizontal well. Consequently, it can be advantageous to incorporatethe effects of stress overlap into the determination of a multi-stagehydraulic fracturing system for a reservoir in order to optimize or atleast partially improve stimulated reservoir volume (“SRV”).

FIG. 3 is a table illustrating relationships between hydraulic fracturegeometry, stress anisotropy and brittleness of exemplary reservoirformations according to the disclosure. In at least one embodiment, amethod as disclosed herein can include defining the so-called“fracability” of a formation, which can, but need not, occur afterdetermining a horizontal or other well direction for an intendedmulti-stage fracturing design (e.g., transverse). The fracability andresulting hydraulic fracture geometry can be estimated, approximated orotherwise defined by the stress anisotropy and brittleness of aformation, such as a resource shale and/or tight reservoir formation.The term fracability refers to the anticipated geometry or complexity offractures likely to form in a formation (which can be any formation) asa result of hydraulic fracturing operations relative to fracturegeometry in another formation or portion of the same formation. Asillustrated in FIG. 3, in at least some cases, such geometry can rangefrom planar fractures to complex network fractures. Generally, aformation having a higher fracability means that formation is morelikely to exhibit relatively complex hydraulic fractures than aformation having a lower fracability. As the complexity of fracturingincreases from planar to complex, reservoir contact and non-proppedfracture conductivity can increase. In at least one embodiment of thepresent disclosure, the fracability and resulting hydraulic fracturegeometry of a formation can be estimated or otherwise incorporated intoa method and/or system for hydraulically fracturing a formation along awellbore. Factors that can control or otherwise affect the fracabilityand consequent fracture geometry of a formation can include geologicalstresses (e.g. in-situ stresses) and rock (fracture) mechanicalproperties.

In at least one embodiment, geological stresses and mechanicalproperties of a formation can be represented by brittleness and stressanisotropy, and a method as disclosed herein can include determiningwhich of brittleness and stress anisotropy is more likely to control thehydraulic fracture geometry of a formation. For instance, highbrittleness and low stress anisotropy of a formation encourages morecomplexity of the hydraulic fracture geometry (e.g., more formationcontact and more production). But, when either one of these controllingparameters is unfavorable to the complexity of the hydraulic fracturegeometry (i.e., low brittleness or high stress anisotropy), thecomplexity of the hydraulic fracture geometry diminishes significantly.That is, both the brittleness and stress anisotropy works as thedominant parameters defining the hydraulic fracture geometry. A methodas disclosed herein can further include determining which stressanisotropy direction (e.g., horizontal or vertical) is more likely tocontrol the hydraulic fracture geometry of a formation, as discussedbelow.

In at least one embodiment, a method of modeling a multi-stage hydraulicfracturing system can include representing the geostresses (e.g., ofin-situ stresses) as stress anisotropy in one or more of the horizontaland vertical directions. Horizontal stress anisotropy can be definedusing the following equation (Equation 1):

${HSAI} = \left( \frac{{SH} - {Sh}}{Sh} \right)$

wherein HSAI=horizontal stress anisotropy, SH=maximum horizontal stressand Sh=minimum horizontal stress.

Vertical stress anisotropy can be defined using the following equation(Equation 2):

${VSAI} = \left( \frac{{Sv} - {Sh}}{Sh} \right)$

wherein VSAI=vertical stress anisotropy, Sv=vertical overburden stressand Sh=minimum horizontal stress.

HSAI and VSAI may be expressed as unitless values or, as anotherexample, as percentages. A higher HSAI can indicate that hydraulicfractures are relatively more likely to grow in the direction of SH. Alower HSAI can indicate that hydraulic fractures are relatively lesslikely to grow in the direction of SH, which can result in more complexhydraulic fractures, such as a complex network. Similarly, a higher VSAIcan indicate that hydraulic fractures are relatively more likely to growin the direction of Sv and a lower VSAI can indicate that hydraulicfractures are relatively less likely to grow in the direction of Sv. Theresults for one or more reservoir formations can be correlated orotherwise compared and displayed, such as in a table, chart or graphicaluser interface (“GUI”). Additionally, or alternatively, rock (fracture)mechanical properties in a formation can be represented in terms ofbrittleness. Brittleness can be commonly represented using a brittlenessindex, or pseudo-brittleness index, based on a combination of Young'smodulus and Poisson's ratio. Generally, rock with a higher Young'smodulus and lower Poisson's ratio will be more brittle (i.e., will havea higher brittleness index). A higher brittleness index can indicatethat hydraulic fractures have more of a tendency to grow complex networkfractures. Further, a method as disclosed herein can include determiningan optimal fracturing fluid system, which can include determining anoptimal proppant. Fracturing fluid system and proppant selection can bedecided based on fracability or hydraulic fracture geometry type, whichcan be estimated from stress anisotropy and brittleness as describedelsewhere herein. Based on the estimated hydraulic fracture geometrytype (e.g., planar to complex network), an optimal fracturing fluidsystem and proppant volume, type, and size can be selected (e.g.,crosslinked gel to slick water system).

In at least one embodiment, methods and systems for designing orimplementing an improved multi-stage hydraulic fracturing operation forincreasing the SRV of a reservoir (which can be or include anyreservoir), can include determining one or more modified, ormanipulated, stress anisotropies, such as a manipulated vertical stressanisotropy (VSAI*) or a manipulated horizontal stress anisotropy(HSAI*). For example, manipulated horizontal and vertical stressanisotropies can be determined for one or more reservoir intervalsbetween multi-stage hydraulic fracturing stages. Like HSAI and VSAI,HSAI* and VSAI* may be expressed as unitless values or percentages.

Manipulated horizontal stress anisotropy can be defined using thefollowing equation (Equation 3):

${HSAI}^{*} = \left( \frac{{SH} - {Sh}^{*}}{{Sh}*} \right)$

wherein HSAI*=manipulated horizontal stress anisotropy, SH=maximumhorizontal stress and Sh*=manipulated minimum horizontal stress.

Manipulated vertical stress anisotropy can be defined using thefollowing equation (Equation 4):

${VSAI}^{*} = \left( \frac{{Sv} - {Sh}^{*}}{{Sh}*} \right)$

wherein VSAI*=manipulated vertical stress anisotropy, Sv=verticaloverburden stress and Sh*=manipulated minimum horizontal stress.

The manipulated minimum horizontal stress Sh* can be the increase instress in the Sh direction caused by stress overlap due to fracturing(e.g., hydraulic fracturing pressure and hydraulic fracture opening). Inthis manner, a more accurate SRV can be estimated for a reservoir athand. Further, an improved multi-stage hydraulic fracturing plan can bedeveloped and implemented.

FIG. 4 is a perspective view illustrating one of many examples of stressoverlap in an alternating sequence fracturing operation according to thedisclosure. As described above, a stress overlap increase can resultfrom a third hydraulic fracture located in between (which can beanywhere in between) two existing or other hydraulic fractures. In atleast one embodiment of the present disclosure, stress overlap can bemodeled or otherwise represented by numerical stress analysis, which caninclude modeling stress overlap or potential effects of fractures ofincreasing complexity using the discrete element method or finiteelement analysis. In the example shown for illustrative purposes in FIG.4, a brittleness index of 50 percent has been assumed, along with astrike-slip faulting stress regime (i.e., SH>overburden>Sh). Of course,this need not, and likely will not, always be the case, as thebrittleness, stress regime and other factors may vary from formation toformation. In the example of FIG. 4, which is but one of many, thenumerical stress analysis shows the stress in the Sh direction (normalto the hydraulic fracture planes P1, P2, P3) increases approximately 55percent, and the consequent stress anisotropy decreases from about 95percent to about 30 percent. Also, the example analysis discloses theincrease of treating pressure (e.g., more than 6 percent) for the thirdfracture to create a similar fracture volume. However, the treatingpressure may not account for potential complex fractures, which can becreated. That is, the actual treating pressure increase can be higherwhen associated with potential complex fractures created between theprevious two fracture stages.

FIG. 5 is a flow diagram illustrating a method for implementing one ofmany embodiments of a hydraulic fracturing model according to thedisclosure. In at least one embodiment, the flow diagram can include (asgenerally indicated at block 500) modeling, recommending or otherwisedetermining a fracture fluid system based on geomechanical information,such as geostresses and formation properties, and an estimation or otherdetermination of the type and complexity of hydraulic fractures that mayoccur as a result of fracturing operations in a formation or portion ofa formation, which can be or include any formation or portion of aformation according to an application. The flow diagram can also includeanalyzing one or more geomechanical data sets, determining one or morefracture geometries, calculating one or more values representingbrittleness, calculating one or more values representing HSAI,calculating one or more values representing VSAI, and recommending,outputting or otherwise determining one or more features of a hydraulicfracturing operation. The flow diagram can further include defining atleast one of fracability and hydraulic fracture geometry of a formationbased on one or more of brittleness and stress anisotropy.

As shown in the example embodiment of FIG. 5, which is but one of many,a determination (block 502) may be made whether a formation has arelatively high fracability, a medium fracability, or a low fracability.A relatively high fracability (block 504) can be or include abrittleness of 60-80 percent and an HSAI of 10-30 percent, andcorresponding hydraulic fractures can be of the complex network type(block 506). A relatively low fracability (block 508) can be or includea brittleness of less than 30 percent and an HSAI of any value, andcorresponding hydraulic fractures can be of the planar, or lowcomplexity, type (block 510). Medium fracability (block 512) (as well ashigh and low fracability) formations can include formations having arange of brittleness and HSAI/VSAI values. For example, a mediumfracability, medium brittleness case (block 514) can be or include abrittleness of 30-60 percent and an HSAI greater than 30 percent, andcorresponding hydraulic fractures can be of the complex planar type. Amedium fracability, high brittleness case (block 520) can be or includea brittleness of 60-80 percent and an HSAI greater than 100 percent, andcorresponding hydraulic fractures can be of the complex planar type. Ofcourse, as will be understood by one of ordinary skill having thebenefits of the present disclosure, all of the values and ranges shownand described for FIG. 5 and elsewhere herein are for purposes ofexplanation and illustration only. Such values and ranges may be thesame or different for one or more formations the subject of real-worldapplications, and such values and ranges can, and likely will, differfrom formation to formation and application to application.

With continuing reference to FIG. 5, a method as disclosed herein caninclude performing one or more numerical stress analyses and definingfrac spacing, such as an at least potentially optimal frac spacing, fora formation based on one or more target stress values for the formation.A target stress value, such as a target HSAI* or a target VSAI*, can beor include a single value, multiple values, a range of values, acombination thereof, or as another example, a value that is related insome way to the foregoing. A target stress value or set of target stressvalues can represent or otherwise indicate one or more locations forperforating a wellbore. As shown for illustrative purposes in FIG. 5, atarget stress value for a medium fracability, medium brittleness casecan, but need not, be or include an HSAI range of 10-30 percent (block516). As another example, a target stress value for a mediumfracability, high brittleness case can, but need not, be or include anHSAI range of 10-30 percent and a VSAI range of greater than 10 percent(block 522).

In at least one embodiment, which is but one of many, an optimal orotherwise desirable frac spacing can be determined by defining two ormore perforation locations having frac spacing(s) there between,modeling a perforation and fracture complexity at one of more of theperforation locations, modeling the resulting production, and repeatingthe foregoing steps for different perforation locations and fracspacing. The production models can be compared and perforation locationsand frac spacing can be determined for a particular formation at hand,which can be any formation (including any portion of a formation). Forexample, perforation locations and frac spacing can be recommended orchosen for a physical formation according to which production modelpredicts the most desirable results, which can be or include any result,such as, but not limited to, the greatest production. Additionally, oralternatively, a method as disclosed herein can include determining afrac fluid system for use with the formation, which can include a fracfluid alone or a fluid in combination with one or more proppants. Asshown in the exemplary embodiment of FIG. 5, which is but one of many, alow viscosity, fine proppant frac fluid system in combination withrelatively large frac spacing (e.g., slick-water fluid, 100 meshproppant, and ≧300 feet frac spacing) can be advantageous for one ormore high fracability, complex network fracture formations, whereas ahigh viscosity, coarse proppant frac fluid system (e.g., cross-linkedgel fluid, 20/40 mesh proppant) can be advantageous for one or more lowfracability, planar fracture formations. In at least one embodiment, amethod as disclosed herein can include determining frac spacing based onthe quality of the reservoir formation, such as by simulating thereservoir as a computer model or otherwise.

In medium fracability, complex planar fracture formations, other fracfluid systems and frac spacings can be advantageous. As will beunderstood by a person of ordinary skill in the art having the benefitsof the present disclosure, one or more of the systems and methodsdisclosed herein can include estimating or otherwise determining anoptimized or at least partially improved frac fluid system or fracspacing for a formation based on improved fracability or productionestimations derived from a comparison of two or more model iterationsconstructed according to the disclosure, separately or in combination,in whole or in part (generally indicated at block 518 and 524). Morespecifically, many resource shale or tight formations have mediumfracability, which can include having medium brittleness (e.g., 30-60percent) and medium to high HSAI (e.g., 30-100 percent or greater than100 percent), or high brittleness (e.g., 60-70 percent) and high HSAI(e.g., greater than 100 percent), separately or in combination, in wholeor in part. For at least some medium-fracability formations, a hybridfrac fluid system can be used, which can include starting with a lowviscosity, fine proppant frac fluid and ending up with a high viscosity,coarse proppant frac fluid. However, the fracability of such formationscan be improved or increased and the consequent complexity of hydraulicfractures can be enhanced artificially, and in at least one embodiment,the systems and methods disclosed herein can include at least partiallyimproving the enhancement and estimating a magnitude of such enhancementor improvement.

With continuing reference to FIG. 5, in at least one embodiment, amethod as disclosed herein can include decreasing frac spacing in amulti-stage hydraulic fracturing design (e.g., from 300 feet to 150feet) and increasing stresses in a formation between two or morehydraulic fractures, such as by creating or increasing stress overlap. Amethod as disclosed herein can include increasing stress overlap in adirection normal or about normal to one or more hydraulic fractures(i.e., increasing Sh) and decreasing HSAI in at least a portion of theformation (see Equation 1). A method as disclosed herein can includeestimating a decrease in HSAI, which can include performing a numericalstress analysis for at least a portion of the formation (see, e.g., FIG.4), such as an analysis based on data representing one or more ofgeostresses, formation rock properties and net pressure, separately orin combination, in whole or in part. Such data can, but need not, beobtained from a conventional single hydraulic fracture operation(s). Inat least one embodiment, a method as disclosed herein can includedetermining or identifying a target HSAI for a formation, modeling theformation, and iteratively or otherwise determining at least one of afrac spacing and a frac fluid system that at least partially achievesthe target HSAI. A method as disclosed herein can include producing aset of instructions for achieving the target HSAI and hydraulicallyfracturing a wellbore according to the instructions, which can includeat least one of initially hydraulically fracturing a wellbore andmodifying a prior hydraulic fracturing system for a wellbore, such as bychanging a frac fluid, proppant or spacing. In at least one embodiment,a method as disclosed herein can include limiting or otherwisecontrolling a change to Sh for maintaining VSAI at or near a value orwithin a range of values (see Equations 1, 2). For example, in someformations, such as in a medium-frac ability formation having highbrittleness and high HSAI, a fracturing configuration based on arelatively low target HSAI (e.g., 10-30 percent) can result in thegeneration of horizontal or other fractures that may be unintended orundesirable. In such cases, or in other applications, a method accordingto the disclosure can include determining one or more limits for Sh formaintaining a VSAI greater than zero (e.g., 10 percent or another valuegreater than zero). However, this need not be the case, andalternatively, or collectively, an Sh value can result in a VSAI lessthan or equal to zero.

One or more other embodiments of the systems and methods of the presentdisclosure will now be described, which systems and methods can becombined, in whole or in part, with those described above. In at leastone embodiment, a method as disclosed herein can include building ageomechanical model of a formation, performing a petrophysical fractureanalysis of the formation, performing a hydraulic fracturing design forone or more fractures along a wellbore through or in the formation,performing a stress analysis of the formation based on one or morefractures and performing a reservoir simulation of production from theformation via the wellbore as fractured. Hydrocarbon formations canexhibit various types or shapes of fractures upon being subjected tohydraulic fracturing operations. As describe above, for example,depending on the formation and one or more of the other factorsdescribed herein (or other factors that may be known in the art),hydraulically fractured formations can exhibit simple fractures, complexfractures, complex fractures with fissure openings and others, such ascomplex fracture networks comprised of numerous fractures, which caninclude any type of fractures in fluid communication with one another,in whole or in part. The types of fractures in a particular formation orreservoir can relate to one or more characteristics of the formationand/or of the materials present in the formation. These characteristicscan include, for example, stress anisotropy and brittleness, amongothers, such as mineralogy, rock strength, porosity, permeability,content of clay or other types of earth, total organic carbon (“TOC”)content, thermal maturity, gas content, gas-in-place, organic contentand organic maturity, separately or in combination, in whole or in part.The attributes and characteristics of a formation, and the types offractures expected to result from hydraulic fracturing of such aformation, can affect one or more considerations when consideringpotential fracturing approaches, such as, for example, a completionfocus. Other factors that can influence frac design can include theresults of testing performed on a reservoir or formation, such as logand core analyses, which, if present, can be incorporated into one ormore of the systems and methods disclosed herein. In at least oneembodiment, a method as disclosed herein can include determining,estimating or defining, which can include modeling, any of horizontal orother well direction, the number of perforation clusters, the spacingbetween perforation clusters, the location for each perforation cluster,the type of frac fluid and the injection rate of frac fluid, among otherfactors, such as the kind of proppant and the amount of proppant.

The systems and methods of the present disclosure can be used during anyphase of development of a formation, which can be any formationaccording to a particular application. For example, the systems andmethods of the present disclosure can be used during exploration phases,well planning phases, well development phases and other phases, such asdrilling optimization or completion optimization, separately or incombination, in whole or in part. In at least one embodiment, a methodas disclosed herein can include building a geomechanical model, such asa 1D, 2D or 3D model, performing a core analysis (e.g., for determininganisotropy and/or heterogeneity of one or more materials, such asshale), performing a pore pressure analysis, performing an in-situstress analysis and estimating one or more mechanical properties of aformation. In at least one embodiment, a method as disclosed herein caninclude performing a drilling optimization analysis, which can, but neednot, include performing a wellbore stability analysis for determiningshear failure, time dependency, casing shear, critically stressedfractures or faults or other factors or parameters. A drillingoptimization analysis can, but need not, include performing a wellboretrajectory analysis for determining (whether by certainty or estimation)the trajectory of one or more wellbores. Such analyses can result in theidentification of one or more parameters for an optimal drilling design,such as mud weight, mud chemistry, trajectory or other factors, such ascasing type. In at least one embodiment, a method as disclosed hereincan include performing a completion optimization analysis, such as fordetermining a reservoir-specific, multi-stage or other hydraulicfracturing design. For example, such a method as disclosed herein caninclude determining horizontal wellbore direction, defining fracability,determining fracture geometry, assessing the risk of fault reactivation,determining optimal lateral well spacing and other steps, such as, forexample, determining hydraulic fracture interval (i.e., spacing) andpinpointing or otherwise determining one or more optimal hydraulicfracture (i.e., perforation) locations along one or more wellbores. Asused herein, the terms formation and reservoir are synonymous unlessotherwise indicated, and both terms can include an entire formation or aportion of a formation.

In at least one embodiment, a method as disclosed herein can includecreating, processing or otherwise analyzing a series of models, whichcan include 1D, 2D and/or 3D models, and estimating, recommending orotherwise identifying an optimal (or at least potentially advantageousin one or more ways) hydraulic fracturing (“HF”) operation or “fracdesign” for a wellbore, which can include a single- or multi-stage fracdesign. For example, a method as disclosed herein can include analyzinga drilling model, analyzing a stress model, analyzing a basin model,analyzing a seismic model and analyzing one or more other models, suchas a geographical (e.g., regional, local or otherwise) scale model, anumerical stress model or a thermal model, separately or in combination,in whole or in part. A method as disclosed herein can include modelingand analyzing any of numerous factors associated with one or moreformations or wellbores, such as salt content, production, injection,sanding, geothermal and/or other factors, such as one or more of thefactors or parameters described elsewhere herein. In at least oneembodiment, one or more existing software applications can be used todevelop or otherwise analyze one or more of the models described herein,such as, for example, Drillworks Predict®, Geostress®, Presage®, orDrillworks 3D®. However, this need not be the case, and alternatively,or collectively, one or more software applications can be independentlydeveloped for embodying the systems and methods of the presentdisclosure, separately or in combination with one another or one or moreexisting applications.

In at least one embodiment, a method as disclosed herein can includeinputting, considering, processing or otherwise analyzing dataassociated with one or more formations or wellbores, which can includeactual data collected, estimated data, predicted data, calculated data,and/or any other data according to a particular application, such asknown data from operations that have taken or are taking place within orfor one or more other formations or wellbores. For example, formationdata can be or include data or other information gathered from wirelineoperations, logging-while-drilling (“LWD”) operations, core tests andother testing or analyses. In at least one embodiment, a method asdisclosed herein can include analyzing formation data regarding any oneor more of lithology (e.g., gamma ray), resistivity, pore pressure,sonic data (e.g., oriented crossed-dipole), mechanical and other rockproperties, density, temperature, pressure, overburden, wellborestability, formation images, formation stresses, natural fractures, uni-or multi-axial compression, compression considering shale or otheranisotropy (e.g., normal and parallel to bedding), Young's modulus(e.g., vertical and horizontal), Poisson's ratio (e.g., vertical andhorizontal), mineralogy (e.g., x-ray detraction (“XRD”), time-dependentwellbore stability, fluid-rock interaction (e.g., capillary suction time(“CST”) testing, proppant embedment, Brinnell hardness, hole size, welldepth, shear, tensile forces, spalling, formation material(s), breakout,drilling induced fractures (e.g., tensile fractures), stress regions,world stress maps, in-situ stress regimes (e.g., extensional regimes,strike-slip regimes, compressional regimes), drilling instability,wellbore instability, faulting (e.g., normal faulting, strike slipfaulting, reverse faulting), instabilities with and/or withoutconsideration of anisotropy (e.g., shale anisotropy) and/or holecleaning, flow rates, fracture size, fluid type, proppant concentration,fluid volume, proppant volume, number of fracture stages, effectiveconfining pressure, effective mean stress, layering, shale or otherformation material quality, trajectory, efficiency, separately or incombination, in whole or in part.

In at least one embodiment, a method as disclosed herein can includecreating a seismic interval velocity model of a formation, creating apore pressure gradient model of a formation, creating an overburdengradient model of a formation and creating a fracture gradient model ofa formation. A method as disclosed herein can include analyzing in-situstresses, which can include determining an applicable stress regime,determining an applicable fault type and determining one or more effectsof stresses and faults on one or more wellbores. A method as disclosedherein can include determining the manner in which wellbore stabilitycan vary according to wellbore location and position, which can includedetermining a most stable direction, a least stable direction andrelative stabilities in one or more other directions. A method asdisclosed herein can include determining a zero stress anisotropydirection in a formation and how or whether such a direction various,such as according to one or more stresses in one or more stressdirections within the formation. A method as disclosed herein caninclude modeling, predicting or otherwise analyzing the complexity ofone or more hydraulic or other fractures based on in-situ or otherstresses present in a formation. A system can include a datasetrepresenting one or more HF factors, such as a dataset relating fracturegeometry to one or more parameters that can control or otherwise affectfracture geometry resulting from hydraulic fracturing. For example, adataset can include information regarding fracture geometry type, stressanisotropy, brittleness, completion focus and one or more reservoirs,and can relate or compare such information as it relates to the one ormore reservoirs. In at least one embodiment, a dataset can represent therelative presence or magnitude of reservoir contact, fractureconductivity and natural fractures among one or more formations, such asbased on one or more attributes of the formation(s), e.g., brittleness,Young's modulus, Poisson's ratio and/or one or more of the other factorsdescribed herein.

In at least one embodiment, a method as disclosed herein can includedefining a location, spacing, number, direction and sequence ofperforations for one or more wellbores, analyzing the SRV, changing oneor more of the foregoing factors, re-analyzing the SRV for the one ormore wellbores, and determining the differences in the SRV (or othercharacteristics) in light of the changes. A method as disclosed hereincan include performing these steps manually, automatically or otherwise,separately or in combination, in whole or in part, and can includeperforming any of the steps in any order and in any number ofiterations. A method as disclosed herein can include identifying one ormore parameters that can control HF geometry in a formation, which canbe or include any of the parameters and other factors described herein.A method as disclosed herein can include selecting a frac fluid andproppant system for a formation based on one or more controllingparameters of HF geometry within the formation. A method as disclosedherein can include monitoring any of the parameters and other factorsdescribed herein during production operations and changing one or moreaspects of a frac design for a formation. In at least one embodiment,which is but one of many, a method as disclosed herein can includemodeling or otherwise analyzing the characteristics of a reservoir overa distance or length of a wellbore, which can be any distance accordingto a particular application. The method can include analyzing the stressanisotropy and brittleness index (or fracability) of that portion of thereservoir, comparing the foregoing information, and identifying one ormore locations at which to perforate the formation for promoting (or atleast potentially promoting) the best possible production from thatformation. The method can include determining a fracturing system foruse in the area(s) analyzed. In this manner, at least partiallyoptimized production and minimized costs can be achieved by combiningpetrophysical reservoir characteristics and geomechanical fracabilityanalyses along one or more horizontal wells in or through a formation. Amethod for optimizing production from a well can include combiningpetrophysical and geomechanical analyses for determining preferredhydraulic fracturing locations, directions and sequences. Geophysicaland petrophysical analyses on natural fractures and faults can also beused, for example, for designing final or other multi-stage hydraulicfracture systems.

In at least one embodiment, a system for modeling a multi-stagefracturing operation can be or include a computerized model of one ormore of any of wellbores, formations, stresses, stress anisotropies,brittleness, hydraulic fractures, perforation types, perforationspacings, fracturing fluids, proppants, drilling equipment, pipes,drilling fluids and the other factors, variable and attributes describedherein. In at least one embodiment, a system for modeling a multi-stagefracturing operation can be implemented, in whole or in part, usingsoftware, such as one or more of the software applications describedabove. The software can include, for example, routines, programs,objects, components, and data structures for performing particular tasksor implementing particular data types, such as abstract or other datatypes. The interface(s) and implementations of the present disclosuremay reside on a suitable computer system (which can be any computer orsystem of computers required by a particular application) having one ormore computer processors, such as an Intel Xeon 5500, and computerreadable storage, which may be accessible through a variety of memorymedia, including semiconductor memory, hard disk storage, CD-ROM andother media now known or future developed. One or more embodiments ofthe disclosure may also cooperate with one or more other systemresources, such as Oracle® Enterprise, and suitable operating systemresources, such as Microsoft® Windows®, Red Hat® or others, separatelyor in combination.

One or more embodiments of Applicants' disclosure can cooperate withother databases and resources available to a multi-stage fracturingsystem or network. For example, at least one implementation maycooperate with one or more databases, such as a database accessible onthe same computer, over a local data bus, or through a networkconnection. The network connection may be a public network, such as theInternet, a private network, such as a local area network (“LAN”), orsome combination of networks. Those skilled in the art having thebenefits of Applicants' disclosure will appreciate that one or moreembodiments of the disclosure may be implemented in a variety ofcomputer-system configurations, or computer architectures. It will beappreciated that any number of computer systems and computer networksare acceptable for use in embodiments of the disclosure. Still furtherembodiments may be implemented in distributed-computing environments,such as where tasks are performed by remote-procressing devices that maybe linked through a communications network. In a distributed-computingenvironment, program modules may, but need not, be located in both localand remote computer-storage media, including memory storage devices orother media.

One or more embodiments of the disclosure can be stored on computerreadable media, such as one or more hard disk drives, DVDs, CD ROMs,flash drives, or other semiconductor, magnetic or optically readablemedia, separately or in combination, in whole or in part. These computerstorage media may carry computer readable instructions, data structures,program modules and other data representing one or more embodiments ofthe disclosure, or portions thereof, for loading and execution by animplementing computer system. Although one or more other internalcomponents of a suitable computing system may not be specifically shownor described herein, those of ordinary skill in the art will appreciatethat such components and their interconnection and operation are wellknown.

In at least one embodiment of the disclosure, data federation or othertechniques can be used to combine information from one or moredatabases, such as information regarding one or more formations or othercharacteristics thereof, separately or in combination with informationfrom one or more other sources (e.g., those described elsewhere herein),into a system for optimizing a model of a hydraulic fracturing system ordesign. This can be accomplished according to a computer implementedprocess that synchronizes (e.g., periodically, continuously orotherwise) the model with, for example, the most current informationabout a physical oilfield formation available at a particular time ortimes of interest to a user. There are many sources of information thatmay be used to provide information into an optimized fracturing modelaccording to embodiments of the disclosure. For example, the database(s)used by Landmark Graphics Corporation's OpenWells® Engineering DataModel (“EDM”), those used by Peloton's Wellview® (MasterView), or otherwell drilling operational databases, may provide data such as thelatitude and longitude of wells in a formation(s). Also, oralternatively, a system according to the disclosure can includeformation information from one or more geographical information systems(“GIS”), public data sources, or other sources, such as databasesincluding information regarding materials (e.g., material factors, typesor properties), component sizes (e.g., diameters, lengths, etc.),friction factors, or variable described elsewhere herein. Of course, anyor all data from a particular source can be considered or otherwise usedas required or desired for a particular application of an embodiment, inwhole or in part, separately or in combination, and in at least someembodiments may be used to obtain other information that may not beimmediately available in a particular form or format. For example, ifdesired formation information is not explicitly included in a sourcedatabase, such information can be determined from other information inat least some cases.

FIG. 6 illustrates an exemplary system 600 that may be used inperforming all or a lease portion of the well fracturing design andmodeling process described herein. The exemplary system 600 may be aconventional workstation, desktop, or laptop computer, or it may be acustom computing system 600 developed for a particular application. In atypical arrangement, the system 600 includes a bus 602 or othercommunication pathway for transferring information among othercomponents within the system 600, and a CPU 604 coupled with the bus 602for processing the information. The system 600 may also include a mainmemory 606, such as a random access memory (RAM) or other dynamicstorage device coupled to the bus 602 for storing computer-readableinstructions to be executed by the CPU 604. The main memory 606 may alsobe used for storing temporary variables or other intermediateinformation during execution of the instructions by the CPU 604.

The system 600 may further include a read-only memory (ROM) 608 or otherstatic storage device coupled to the bus 602 for storing staticinformation and instructions for the CPU 604. A computer-readablestorage device 610, such as a nonvolatile memory (e.g., Flash memory)drive or magnetic disk, may be coupled to the bus 602 for storinginformation and instructions for the CPU 604. The CPU 604 may also becoupled via the bus 602 to a display 612 for displaying information to auser. One or more input devices 614, including alphanumeric and otherkeyboards, mouse, trackball, cursor direction keys, and so forth, may becoupled to the bus 602 for communicating information and commandselections to the CPU 604. A communications interface 616 may beprovided for allowing the horizontal well design system 600 tocommunicate with an external system or network.

In accordance with the exemplary disclosed embodiments, one or morehydraulic fracturing modeling applications 618, or the computer-readableinstructions therefor, may also reside on or be downloaded to thestorage device 610 for execution. In general, the one or moreapplications 618 are or include one or more computer programs that maybe executed by the CPU 604 and/or other components to allow users toperform some or all the hydraulic fracturing design and modeling processdescribed herein. Such applications 618 may be implemented in anysuitable computer programming language or software development packageknown to those having ordinary skill in the art, including variousversions of C, C++, FORTRAN, and the like.

Accordingly, as set forth above, the embodiments disclosed herein may beimplemented in a number of ways. In general, in one aspect, theexemplary embodiments include a computer-implemented method of designinga hydraulic fracturing operation for a hydrocarbon reservoir. The methodcomprises defining an anisotropy of a formation material in thereservoir, defining a heterogeneity of a formation material in thereservoir, and creating, in computer readable storage, an electronicallystored geomechanical model of at least a portion of the reservoir basedon at least the anisotropy and the heterogeneity, wherein thegeomechanical model exhibits a prediction of at least one of porepressure and in-situ stresses within the portion of the reservoir. Themethod also comprises defining a wellbore path in the geomechanicalmodel through the portion of the reservoir, and identifying an estimatedhydraulic fracturing geometry of the portion of the reservoir at firstand second fracturing locations along the wellbore path, wherein theestimated hydraulic fracturing geometry is based on at least one of ageostress and a formation material mechanical property existing at thefirst and second fracturing locations. The method additionally comprisescreating, in computer readable storage, an electronically storedfracturing geometry model of the estimated hydraulic fracturing geometryat the first and second fracturing locations, estimating a firststimulated reservoir volume of the portion of the reservoir, and addingto the electronically stored fracturing geometry model an estimatedhydraulic fracturing geometry at a third fracturing location along thewellbore path between the first and second fracturing locations. Themethod further comprises calculating a manipulated stress anisotropy ofthe portion of the reservoir based on the addition of the estimatedhydraulic fracturing geometry at the third fracturing location,estimating a second stimulated reservoir volume of the portion of thereservoir; and calculating a difference between the first stimulatedreservoir volume and the second stimulated reservoir volume.

In some embodiments, the method may further comprise any one of thefollowing features individually or any two or more of these features incombination, including: changing at least one variable within thefracturing geometry model, recalculating the manipulated stressanisotropy, and estimating a third stimulated reservoir volume of theportion of the reservoir; the at least one variable is selected from thegroup consisting of well interval, perforation interval, perforationorder and a combination thereof; performing a numerical stress analysisof a reservoir interval between the first and second fracturinglocations; the third fracturing location is disposed within a reservoirinterval and located a first perforation interval from the firstfracturing location and a second perforation interval from the secondfracturing location, and wherein the method further comprisesdetermining a change in stress in one or more directions within thereservoir interval; determining a change in treating pressure based onthe change in stress; determining a likelihood that hydraulic fracturingat the third fracturing location will cause fractures of increasedcomplexity in the reservoir interval between the first and secondfracturing locations; determining a manipulated horizontal stressanisotropy (HSAI*) of the reservoir interval based on the first andsecond perforation intervals, wherein HSAI* is determined according tothe equation:

HSAI

̂*=(SH-

Sh

̂*)/(Sh*); determining a plurality of HSAI* values based on a pluralityof different values for at least one of the first and second perforationintervals; identifying a position of the third fracturing location alongthe reservoir interval at which a target HSAI* value exists; determininga manipulated vertical stress anisotropy (VSAI*) of the reservoirinterval, wherein VSAI* is determined according to the equation:

VSAI

̂*=(Sv-

Sh

̂*)/(Sh*); and identifying a position of the third fracturing locationalong the reservoir interval at which a target VSAI* value exists

In general, in another aspect, the exemplary embodiments include acomputer-based system for designing a hydraulic fracturing operation fora hydrocarbon reservoir. The computer-based system comprises a centralprocessing unit mounted within the computer-based system, a data inputunit connected to the central processing unit, the data input unitreceiving fracability data pertaining to the hydrocarbon reservoir, adatabase connected to the central processing unit, the database storingthe fracability data for the hydrocarbon reservoir, and a storage deviceconnected to the central processing unit, the storage device storingcomputer-readable instructions therein. The computer-readableinstructions are executable by the central processing unit to performthe method of designing a hydraulic fracturing operation for ahydrocarbon reservoir as substantially described above.

In general, in yet another aspect, the exemplary embodiments include acomputer-readable medium storing computer-readable instructions forcausing a computer to design a hydraulic fracturing operation for ahydrocarbon reservoir. The computer-readable instructions comprisesinstructions for causing the computer to perform the method of designinga hydraulic fracturing operation for a hydrocarbon reservoir assubstantially described above.

The role of the systems and methods of the present disclosure can becontinuous throughout the life of an unconventional or other reservoir,and can be focused during exploration, well planning and developmentphases, such as when optimizing multi-stage hydraulic fracturing design.The systems and methods disclosed herein can enhance hydrocarbonproduction and reduce costs by minimizing learning curves associatedwith one or more formations, such as emerging resource shale and tightplays.

Other and further embodiments utilizing one or more aspects of thesystems and methods described above can be devised without departingfrom the spirit of Applicants' disclosures. For example, the systems andmethods disclosed herein can be used alone or to form one or more partsof another modeling, simulation or other analysis system. Further, thevarious methods and embodiments of the workflow system can be includedin combination with each other to produce variations of the disclosedmethods and embodiments. Discussion of singular elements can includeplural elements and vice-versa. References to at least one item followedby a reference to the item may include one or more items. Also, variousaspects of the embodiments can be used in conjunction with each other.Unless the context requires otherwise, the word “comprise” andvariations such as “comprises” or “comprising” should be understood toimply the inclusion of at least the stated element or step or group ofelements or steps or equivalents thereof, and not the exclusion of agreater numerical quantity or any other element or step or group ofelements or steps or equivalents thereof. The order of steps can occurin a variety of sequences unless otherwise specifically limited. Thevarious steps described herein can be combined with other steps,interlineated with the stated steps, and/or split into multiple steps.Similarly, elements have been described functionally and can be embodiedas separate components or can be combined into components havingmultiple functions.

As will be appreciated by those skilled in the art, one or moreembodiments of the present disclosure may be embodied as a method, dataprocessing system, or computer program product. Accordingly, at leastone embodiment may take the form of an entirely hardware embodiment, anentirely software embodiment, or an embodiment combining software andhardware aspects. Furthermore, at least one embodiment may be a computerprogram product on a computer-usable storage medium having computerreadable program code on the medium. Any suitable computer readablemedium may be utilized including, but not limited to, static and dynamicstorage devices, hard disks, optical storage devices, and magneticstorage devices.

At least one embodiment may be described herein with reference toflowchart illustrations of methods, systems, and computer programproducts according to the disclosure. It will be understood that eachblock of a flowchart illustration, and combinations of blocks inflowchart illustrations, can be implemented by computer programinstructions. These computer program instructions may be provided to aprocessor of a general purpose computer, special purpose computer, orother programmable data processing apparatus to produce a machine, suchthat the instructions, which can execute via a processor of a computeror other programmable data processing apparatus, can implement thefunctions specified in the flowchart block or blocks, separately or incombination, in whole or in part.

The computer program instructions may be stored in a computer-readablememory that can direct a computer or other programmable data processingapparatus to function in a particular manner, such that the instructionsstored in the computer-readable memory result in an article ofmanufacture including instructions which can implement the function(s)specified in the flowchart block or blocks. The computer programinstructions may be loaded onto a computer or other programmable dataprocessing apparatus to cause a series of operational steps to beperformed on the computer or other programmable apparatus to produce acomputer implemented process such that the instructions which execute onthe computer or other programmable apparatus provide steps forimplementing the functions specified in the flowchart block or blocks.

While the disclosed embodiments have been described with reference toone or more particular implementations, those skilled in the art willrecognize that many changes may be made thereto without departing fromthe spirit and scope of the description and that obvious modificationsand alterations to the described embodiments are available. Accordingly,each of these embodiments and obvious variations thereof is contemplatedas falling within the spirit and scope of the disclosure and, inconformity with the patent laws, Applicants intend to fully protect allsuch modifications and improvements that come within the scope or rangeof equivalents of the following claims.

What is claimed is:
 1. A computer-implemented method of designing ahydraulic fracturing operation for a hydrocarbon reservoir, comprising:defining an anisotropy of a formation material in the reservoir;defining a heterogeneity of a formation material in the reservoir;creating, in computer readable storage, an electronically storedgeomechanical model of at least a portion of the reservoir based on atleast the anisotropy and the heterogeneity, wherein the geomechanicalmodel exhibits a prediction of at least one of pore pressure and in-situstresses within the portion of the reservoir; defining a wellbore pathin the geomechanical model through the portion of the reservoir;identifying an estimated hydraulic fracturing geometry of the portion ofthe reservoir at first and second fracturing locations along thewellbore path, wherein the estimated hydraulic fracturing geometry isbased on at least one of a geostress and a formation material mechanicalproperty existing at the first and second fracturing locations;creating, in computer readable storage, an electronically storedfracturing geometry model of the estimated hydraulic fracturing geometryat the first and second fracturing locations; estimating a firststimulated reservoir volume of the portion of the reservoir; adding tothe electronically stored fracturing geometry model an estimatedhydraulic fracturing geometry at a third fracturing location along thewellbore path between the first and second fracturing locations;calculating a manipulated stress anisotropy of the portion of thereservoir based on the addition of the estimated hydraulic fracturinggeometry at the third fracturing location; estimating a secondstimulated reservoir volume of the portion of the reservoir; andcalculating a difference between the first stimulated reservoir volumeand the second stimulated reservoir volume.
 2. The method of claim 1,further comprising iteratively changing at least one variable within thefracturing geometry model, recalculating the manipulated stressanisotropy, and estimating a third stimulated reservoir volume of theportion of the reservoir.
 3. The method of claim 2, wherein the at leastone variable is selected from the group consisting of well interval,perforation interval, perforation order and a combination thereof. 4.The method of claim 1, further comprising performing a numerical stressanalysis of a reservoir interval between the first and second fracturinglocations.
 5. The method of claim 1, wherein the third fracturinglocation is disposed within a reservoir interval and located a firstperforation interval from the first fracturing location and a secondperforation interval from the second fracturing location, and whereinthe method further comprises determining a change in stress in one ormore directions within the reservoir interval.
 6. The method of claim 5,further comprising determining a change in treating pressure based onthe change in stress.
 7. The method of claim 5, further comprisingdetermining a likelihood that hydraulic fracturing at the thirdfracturing location will cause fractures of increased complexity in thereservoir interval between the first and second fracturing locations. 8.The method of claim 5, further comprising determining a manipulatedhorizontal stress anisotropy (HSAI*) of the reservoir interval based onthe first and second perforation intervals, wherein HSAI* is determinedaccording to the equation:${HSAI}^{*} = {\frac{{SH} - {Sh}^{*}}{{Sh}*}.}$
 9. The method of claim8, further comprising determining a plurality of HSAI* values based on aplurality of different values for at least one of the first and secondperforation intervals.
 10. The method of claim 9, further comprisingidentifying a position of the third fracturing location along thereservoir interval at which a target HSAI* value exists.
 11. The methodof claim 5, further comprising determining a manipulated vertical stressanisotropy (VSAI*) of the reservoir interval, wherein VSAI* isdetermined according to the equation:${VSAI}^{*} = {\frac{{Sv} - {Sh}^{*}}{{Sh}*}.}$
 12. The method of claim11, further comprising identifying a position of the third fracturinglocation along the reservoir interval at which a target VSAI* valueexists.
 13. A computer-based system for designing a hydraulic fracturingoperation for a hydrocarbon reservoir, comprising: a central processingunit mounted within the computer-based system; a data input unitconnected to the central processing unit, the data input unit receivingfracability data pertaining to the hydrocarbon reservoir; a databaseconnected to the central processing unit, the database storing thefracability data for the hydrocarbon reservoir; and a storage deviceconnected to the central processing unit, the storage device storingcomputer-readable instructions therein, the computer-readableinstructions executable by the central processing unit to: define ananisotropy of a formation material in the reservoir; define aheterogeneity of a formation material in the reservoir; create ageomechanical model of at least a portion of the reservoir based on atleast the anisotropy and the heterogeneity, wherein the geomechanicalmodel exhibits a prediction of at least one of pore pressure and in-situstresses within the portion of the reservoir; and define a wellbore pathin the geomechanical model through the portion of the reservoir.
 14. Thecomputer-based system of claim 13, wherein the computer-readableinstructions further cause the central processing unit to identify anestimated hydraulic fracturing geometry of the portion of the reservoirat first and second fracturing locations along the wellbore path, theestimated hydraulic fracturing geometry based on at least one of ageostress and a formation material mechanical property existing at thefirst and second fracturing locations.
 15. The computer-based system ofclaim 14, wherein the computer-readable instructions further cause thecentral processing unit to: create an electronically stored fracturinggeometry model of the estimated hydraulic fracturing geometry at thefirst and second fracturing locations; estimate and a first stimulatedreservoir volume of the portion of the reservoir; and add to theelectronically stored fracturing geometry model an estimated hydraulicfracturing geometry at a third fracturing location along the wellborepath between the first and second fracturing locations.
 16. Thecomputer-based system of claim 15, wherein the computer-readableinstructions further cause the central processing unit to: calculate amanipulated stress anisotropy of the portion of the reservoir based onthe addition of the estimated hydraulic fracturing geometry at the thirdfracturing location; estimate a second stimulated reservoir volume ofthe portion of the reservoir; and calculate a difference between thefirst stimulated reservoir volume and the second stimulated reservoirvolume.
 17. A computer-readable medium storing computer-readableinstructions for causing a computer to design a hydraulic fracturingoperation for a hydrocarbon reservoir, the computer-readableinstructions comprising instructions that, when executed by a processor,cause the computer to: define an anisotropy of a formation material inthe reservoir; define a heterogeneity of a formation material in thereservoir; create a geomechanical model of at least a portion of thereservoir based on at least the anisotropy and the heterogeneity,wherein the geomechanical model exhibits a prediction of at least one ofpore pressure and in-situ stresses within the portion of the reservoir;and define a wellbore path in the geomechanical model through theportion of the reservoir.
 18. The computer-readable medium of claim 17,wherein the computer-readable instructions further cause the computer toidentify an estimated hydraulic fracturing geometry of the portion ofthe reservoir at first and second fracturing locations along thewellbore path, the estimated hydraulic fracturing geometry based on atleast one of a geostress and a formation material mechanical propertyexisting at the first and second fracturing locations.
 19. Thecomputer-readable medium of claim 18, wherein the computer-readableinstructions further cause the computer to: create an electronicallystored fracturing geometry model of the estimated hydraulic fracturinggeometry at the first and second fracturing locations; estimate and afirst stimulated reservoir volume of the portion of the reservoir; andadd to the electronically stored fracturing geometry model an estimatedhydraulic fracturing geometry at a third fracturing location along thewellbore path between the first and second fracturing locations.
 20. Thecomputer-readable medium of claim 19, wherein the computer-readableinstructions further cause the computer to: calculate a manipulatedstress anisotropy of the portion of the reservoir based on the additionof the estimated hydraulic fracturing geometry at the third fracturinglocation; estimate a second stimulated reservoir volume of the portionof the reservoir; and calculate a difference between the firststimulated reservoir volume and the second stimulated reservoir volume.